Gas injection techniques, such as WAG, frequently require consideration of co-existing oil, gas and water phases and the impact of saturation cycles as water and gas slugs move through the reservoir. These processes may be assessed using numerical simulations. This paper presents the analysis of a detailed laboratory study, designed to provide data for verifying hysteresis models for such simulations. A number of studies have reported evidence for hysteresis in gas relative permeabilities in WAG flooding, leading to lower gas mobilities than predicted by conventional two-phase models. A reduction in gas mobility tends to improve gas sweep and incremental recovery for WAG based IOR schemes. Three-phase hysteresis models have recently been developed to include these hysteresis effects. The models include trapping of gas and reduction of water relative permeability in the presence of trapped gas. In these models, saturation changes can be irreversible, and relative permeability may decrease with each change in direction in saturation. A carefully planned laboratory study investigated secondary and tertiary immiscible WAG floods in both water-wet and intermediate-wet Berea cores, giving four separate sets of experimental data (a total of over 30 individual floods). For each flood, in-situ saturation profiles, mass balance and pressure drop data were measured. The in-situ saturation data ensures that laboratory artefacts (such as capillary end effects) do not influence conclusions. Analysis of the experimental data shows that hysteresis models should include the following features:Irreversibility of hysteresis cycles;Potential for the reduction in the residual oil saturation with trapping of gas by water;Reduction in both water and gas permeability, with potential for the fractional flow to vary with trapped gas saturation;Variation in Land trapping factor between hysteresis cycles. This study confirms the need for three-phase hysteresis models. Although published models may include some of the observed hysteresis effects, no model includes them all. Introduction Reservoir engineering calculations frequently require consideration of co-existing oil, gas and water phases. In the case of immiscible hydrocarbon gas WAG flooding, these considerations include the displacement of oil by simultaneous gas-water flow. These displacement processes are usually assessed using numerical simulation. Although the permeability of reservoir rock typically depends on the interstitial pore geometry, the relative permeability depends on factors such as wettability, spreading characteristics and the fluid distribution in the pore space. There is usually more than one way a given fraction of the pore space can be occupied by each fluid phase and so it is possible for different relative permeability values to be measured for the same fluid saturation. The sequence of saturation changes will, therefore, affect fluid distribution and the relative permeability. Historically, hysteresis effects have been included in numerical simulations using empirical models based on two-phase flow [1,2]. Recent investigations have considered hysteresis for more complex three-phase processes and a number of new models have been proposed for inclusion in commercial simulation packages [3,4,5].
Development plans for UKCS viscous oil reservoirs use production profiles predicted by full-field simulation models. The use of horizontal wells, possibly combined with other IOR techniques, and the unusually high vertical permeability of many of the fields, lead to a range of issues that need to be carefully considered when building simulation models. The strengths and weaknesses of different gridding systems, and the level of areal and vertical grid refinement that is needed, are discussed and illustrated with a range of examples including: interpretation of Extended Well Test results and integration with full-field modelling; sensitivity to relative permeability assumptions; prediction of gas movement from primary gas caps; and the comparison of different IOR techniques. Where horizontal wells are drilled to reduce gas coning, undulations in the well trajectory can cause local coning of free gas, giving significantly earlier breakthrough times compared to strictly horizontal wells. A good correlation is found between effective stand-off and breakthrough time. Where localized gas production occurs, scoping calculations suggest that inflow of oil from further down the wellbore may be significantly reduced by multi-phase friction effects and gravity potential terms not modelled in conventional simulators.
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